FERC Mostly Affirms Market-Based Rate Program

On April 21, FERC issued an order generally affirming its market-based rate program, promulgated last June in Order No. 697.  FERC left many of its prior determinations in place, including much of the analysis sellers must provide in order to receive or maintain authority to sell electric energy, capacity, and/or ancillary services at market-based rates. 

In particular, FERC affirmed its decision to combine its prior four-pronged analysis into an evaluation of horizontal and vertical market power.  FERC will continue its approach of using "indicative" screens to determine both a seller's wholesale market share and whether the seller is a "pivotal" supplier within the relevant geographic market.  If a seller fails to pass either of these screens, FERC will presume the seller has market power within that market and require the seller to either (a) refute that it has market power or (b) adopt mitigated (i.e., cost-based) rates for that market.  FERC also affirmed its decision to remove questions about the relationship between market-based rate sellers and their affiliated franchised public utilities from the market-based rate review program, and instead to codify those requirements in FERC's regulations as ongoing obligations that sellers must continue to meet.

FERC did offer certain clarifications or revise certain of its prior determinations on rehearing.  One of FERC's major changes was to allow a seller that has been presumed to have market power in the short-term to continue to show that it does not have market power, and thus may continue to charge market-based rates, with respect to its long-term contracts.  To do so, a seller is required to show that the buyer has other viable alternatives to purchasing power under the contract.  Additionally, with respect to FERC's affiliate restrictions, FERC granted rehearing on its adoption of a prohibition on two-way information sharing between market-based rate sellers and affiliated franchised public utilities with captive customers, determining instead that to adopt a one-way prohibition, i.e., the utility may not provide information to the market-based rate seller.  A few FERC's other notable clarifications included:

• FERC clarified that sellers may make use of ISO/RTO mitigation and/or market monitoring in order to show they do not possess market power and that such mitigation and monitoring will be presumed to be sufficient to address market power concerns, although other parties may present evidence otherwise. 

• FERC made certain clarifying changes with respect to the horizontal market power analysis, which examines whether a seller has generation market power in generation.  In particular, FERC clarified the data that it will rely upon in this analysis.  FERC generally affirmed its decision to rely solely on historical data to determine whether a seller has market power.  However, FERC conceded that it will consider, on a case-by-case basis, "clear and compelling evidence" that certain changes in relevant geographic markets should be taken into account.  Additionally, FERC also provided several clarifications to the transmission import studies that sellers must provide to account for uncommitted generation capacity in their relevant markets.

• FERC clarified that sellers are not required to report on firm transmission rights or congestion contracts (collectively, FTRs) as part of their analyses of their vertical market power, which examines whether a seller has market power with respect to transmission or can erect other barriers to entry.

• FERC codified definitions of "affiliate" and "captive customers" in its regulations, and clarified that the affiliate restrictions in its regulations generally supersede prior "codes of conduct."

FERC Blesses Midwest ISO Plan for Resource Adequacy

The Federal Energy Regulatory Commission has conditionally accepted a Midwest Independent Transmission System Operator (Midwest ISO) plan for ensuring long-term resource adequacy in the RTO’s 15-state territory.  Most other RTOs and ISOs have spent years grappling with how to ensure sufficient capacity is available to meet peak demand, and contentious FERC proceedings have led to different market models in NYISO, PJM, and ISO-NE.  FERC directed MISO to develop its own resource adequacy plan after having operated for years without one.   The first planning year under the resource adequac plan will start June 2009.

MISO’s responsibilities under the new plan will include determining capacity obligations, monitoring compliance, and assessing penalties to deficient load servers.  Unlike the PJM, ISO-NE, and NYISO models, the MISO plan does not entail a centralized capacity market, but does require any load server in the Midwest ISO region to maintain access to sufficient planning resources, whether generation or demand response.  

CAISO Says It Will Announce MRTU Start in July

It is still unclear when the California Independent System Operator's long-awaited Market Redesign and Technology Upgrade (MRTU) will take effect, but the CAISO recently suggested it will announce the startup date in July 2008. 

Ever since the California energy crisis, the CAISO has worked on designing and implementing a new wholesale power market with features such as locational marginal pricing, financial transmission rights (called congestion revenue rights), and a day-ahead market energy market.  The CAISO filed the MRTU proposal with FERC in February 2006, and proposed a market startup date of November 2007.  Due to technical issues and ongoing administrative litigation over the details of the market design, the proposed startup date has been delayed several times, first to February 2008, then April 2008, and now again to an unknown time.   The latest delay raised the prospect of MRTU not taking effect until next fall, after the high-demand summer season, which the CAISO's latest announcement appears to confirm. 

FERC Proposes Sundry Changes to Organized Power Market Rules

In a new rulemaking, the Federal Energy Regulatory Commission (FERC) has resisted pressure from various groups to examine the foundations of organized wholesale power markets administered by RTOs and ISOs, and instead proposes various tweaks to the rules in these markets. 

FERC rejected the calls by the American Public Power Association and others who have argued that organized power markets are failing to produce just and reasonable rates and that FERC should engage in fundamental reform of RTOs and ISO.  Instead, FERC focused its proposals on areas where it stated that improvements were supported by the law, facts and economic theory, but which have also been high-profile of late, whether due to advocacy by individual Commissioners (such as demand response) or because of bitter disputes within or about RTOs (such as market monitoring).  The specific proposals fall into four categories.

          Demand Response

o        Require RTOs and ISOs to accept bids from demand response resources in their markets for certain ancillary services comparable to other resources.

o        During a system emergency, require RTOs and ISOs to eliminate a charge to a buyer for taking less energy in the real-time market than it purchased in the day-ahead market.

o        Require RTOs and ISOs to permit an aggregator of retail customers to bid demand response on behalf of retail customers.

o        Modify market rules to allow market-clearing prices, during a period of operating reserve shortage, to reach a level that rebalances supply and demand so as to maintain reliability while providing sufficient provisions for mitigating market power.

Long-term Power Contracting

o        Require RTOs and ISOs to dedicate a portion of their websites for market participants to post offers to buy or sell power on a long-term basis.

Improved Market Monitoring

o        Require each RTO and ISO to provide its Market Monitoring Unit (MMU) with access to market data, resources and personnel necessary to carry out its duties.

o        Require the MMU to report directly to the RTO or ISO board.

o        Expand the list of recipients who would receive MMU recommendations regarding rule and tariff changes, and broaden the scope of behavior reported to FERC.

o        Remove the MMU from tariff administration, including mitigation, and require each RTO and ISO to include in its tariff ethics standards for MMU employees.

o        Expand dissemination of MMU market information to a broader constituency, with more frequent reports.

Responsiveness to Customers and Stakeholders

o        Adopt principles for RTOs and ISOs to ensure inclusiveness, fairness in balancing diverse interests, representation of minority positions, and ongoing responsiveness.

Comments on the proposed rules are due April 21.  In addition to the proposed reforms, FERC also ordered a technical conference to be held to consider proposals for modifying the design of organized markets, as well as a separate technical conference to discuss barriers to demand response in organized markets.

FERC Allows Duquesne to Exit PJM, but with Conditions

FERC on January 17 conditionally approved Duquesne Light's request to withdraw from the PJM Interconnection and join the Midwest Independent System Operator.  Last November, Duquesne filed an application with FERC seeking approval to leave PJM over rising capacity costs as a result of PJM's new forward capacity market.  In comments and protests filed in December, PJM and other PJM market participants asked FERC to hold Duquesne be held to its financial commitments to the market and ensure that its withdrawal would not harm other market participants financially.

In the January 17 order, FERC agreed to hold Duquesne responsible for its commitments in the PJM forward capacity market.  FERC conditioned Duquesne's right to exit PJM upon the utility honoring commitments for all forward capacity auctions in which its load had been included.  This means that Duquesne will be liable for forward capacity costs through May 2011.  (Duquesne had asked FERC to make its withdrawal from PJM and termination of its obligations in the capacity markets effective May 31, 2008.)  FERC also directed Duquesne to submit further information on its remaining obligations, including how many and what its continuing obligations to PJM are, what its allocated share of costs for the PJM regional transmission planning process is, and how it will be integrated into the Midwest ISO.

FERC Tweaks Open-Access Reforms in Order No. 890-A

In late December FERC issued Order No. 890-A, clarifying and modifying the reforms it made in Order No. 890 to open-access transmission requirements originally established by Order Nos. 888 and 889 and revising the associated pro forma open access transmission tariff. 

In the primary clarifications and modifications, FERC:

• affirmed a tiered approach to calculating energy and generator imbalance charges, while revising the calculation itself:  imbalance charges should be based on the last 10 MW dispatched by the transmission provider for any purpose, rather than the last 10 MW dispatched to serve native load;
• affirmed lifting the price cap on reassignments of transmission capacity for all transmission customers through October 2010 (though the price cap lift may be extended based on a required FERC staff report due in May 2010);
• clarified that the control area of an off-system resource must be identified before it can qualify as a "network" resource, but deferred revising the minimum lead time for undesigating network resources; and
• clarified posting requirements related to processing of service requests and the time frame for implementation of transmission rollover rights reforms. 

As with Order No. 890, transmission providers must submit compliance filings to incorporate the modifications contained in Order No. 890-A—within 60 days of the order's publication in the Federal Register for non-RTO/ISO transmission providers whose facilities are not within an RTO/ISO footprint, and within 90 days for RTO/ISO transmission providers.

No Free Pass for Absconding Duquesne Light, Say PJM and Capacity Suppliers

In December 4, 2007 pleadings to FERC, PJM Interconnection and several PJM member utilities and power suppliers did not oppose Duquesne Light's right to exit PJM’s organized market, but did ask the agency to impose conditions on Duquesne’s withdrawal.  Among those conditions, they asked that Duquesne be required to hold other PJM participants harmless and satisfy all of its PJM contractual agreements, including its existing forward capacity obligations. 

Rising capacity costs were one of the primary reasons Duquesne sought to leave PJM in the first place.  Duquesne applied to FERC in early November for approval to leave PJM and to join the Midwest Independent Transmission System Operator (MISO).  In its filing, Duquesne explained that PJM's reliability pricing model (RPM) has drastically increased its capacity costs—from the $1-$5/MW-day range to over $100/MW-day.  Duquesne also asked that FERC confirm that the utility will not be liable for any RPM-related costs for deliveries that occur after it leaves PJM.

In its December 4 response, PJM argued that Duquesne should be required to “uphold the commitment and obligations it has assumed and [ensure] that other parties do not unfairly shoulder the cost of those obligations.”  PJM also laid blame on Duquesne itself for the Western Pennsylvania utility's unhappiness with the new capacity market, suggesting that Duquesne had relied solely on PJM's capacity auction instead of contracting bilaterally for other sources of capacity.  The Pennsylvania Office of Consumer Advocate asked FERC to ensure that Duquesne's departure does not injure other PJM load servers.  Others, including several PJM capacity suppliers, attacked Duquesne's filing as inadequately supported to justify the drastic measure of leaving PJM. 

No Common Denominator on Capacity Markets

While organized energy market operators generally agree on locational marginal pricing (LMP) as the basic framework for valuing energy, no similar consensus attends capacity markets.  The New York Independent System Operator (NYISO) presently is retooling its capacity market for New York City in response to a FERC order, and the California Independent System Operator (CAISO) continues to wring its hands over the issue of capacity markets. 

Even though Consolidated Edison divested most of its New York City generation when the NYISO was created in 1999, ownership of in-city generation remained concentrated, requiring rules to mitigate installed capacity (ICAP) prices.  When talks about revising the ICAP rules broke down last July, FERC announced its expectation that the NYISO, working with market participants, would develop market rules that ensured long-term reliability without overcompensating generators.  In response, the NYISO proposed to continue to use auctions and a demand curve for pricing capacity, but also to add features such as must-offer obligations for larger suppliers, as well as an offer ceiling and price floors based on a percentage of the cost of new entry, in order to mitigate seller and buyer market power.  The market's response has been mixed.  Some have urged the use of forward capacity markets in the NYISO.  PJM and ISO-NE have adopted variations of that model, which entails procurement of capacity several years in advance, rather than only several months in advance.

Meanwhile, the CAISO continues its stakeholder process to develop a capacity market.  None will be in place as of the commencement of the CAISO’s LMP market in the spring of 2008.  This won’t be unique for organized market operators.  The Midwest ISO has no centralized capacity market, but instead relies on utility compliance with reliability obligations imposed by the applicable states and reliability organizations.  The Electricity Reliability Council of Texas likewise operates an energy-only market.  Concern by the CAISO and state authorities, however, have driven analysis of a potential capacity market in this energy-import dependent state.   But in November the CAISO’s market surveillance committee (MSC) recommended holding off on development of specific capacity market rules.  It pointed out that capacity market rules typically emphasized generator must-offer obligations, whereas the California’s needs tended to be more specific due to its environmental and renewable energy mandates, and reliance on imports, hydropower and intermittent resources.  Generator interests responded to the MSC’s opinion by pointing out capacity market rules were needed to help promote infrastructure development. 

Competing FERC and CFTC Jurisdictional Claims Are Court Bound

FERC in a November 30 order refused to reconsider its July 26 decision to impose $291 million in civil penalties against Amaranth Advisors (Amaranth) for gaming the natural gas futures market and manipulating the price of natural gas.  FERC upheld its own jurisdiction to impose penalties on Amaranth, rejecting the Commodities Futures Trading Commission's (CFTC) insistence that it alone has jurisdiction over manipulation of gas futures contracts.  FERC found instead that "the language and statutory purpose of Section 315 of the Energy Policy Act of 2005" (EPAct 2005) gave FERC "broad authority to sanction manipulative conduct by any entity 'in connection with' the purchase, sale or transport of natural gas within its jurisdiction." 

In the earlier July order, FERC had directed Amaranth to show cause why it had not violated the Natural Gas Act and FERC's anti-market manipulation rules, and proposed a $291 million civil penalty for allegedly manipulating the gas futures market by selling New York Mercantile Exchange (NYMEX) futures contracts just before they expired.  In an August request for rehearing, Amaranth argued that FERC did not have jurisdiction to impose the proposed civil penalties, and that the CFTC had exclusive enforcement authority for manipulation of gas futures markets.  The case has set up a turf war between FERC's expanded enforcement authority under EPAct 2005 and the CFTC's traditional regulation of commodities markets, and led the CFTC to argue that it has exclusive jurisdiction over this case.  Amaranth may now appeal FERC's orders to a US Court of Appeals, which may ultimately delineate the boundaries of FERC's expanded enforcement authority in relation to the CFTC's authority over commodity futures markets. 

Also in the November 30 order, FERC gave Amaranth 14 days to responds to the original show-cause order.

Initiatives Provide Transmission for Renewable Power

The California Energy Commission has initiated a Renewable Energy Transmission Initiative (RETI) to identify transmission projects needed to help the state meet its renewable energy development goals.  In a process similar to that already adopted in Texas, the RETI process entails identifying Competitive Renewable Energy Zones (CREZs) from which renewable energy could be brought to California consumers.  Not surprisingly for the power-importing state, CREZs could be outside as well as inside California, although designation of external CREZs to serve California may not be well received in neighboring states.

The RETI process should complement the California Independent System Operator’s (CAISO) development of transmission financing rules.  The CAISO’s FERC-approved trunkline proposal provides for sharing of costs between interconnecting renewable generators, together with subsidies from other transmission customers.  The CAISO is now working on a tariff proposal for the inelegantly named “Location Constrained Resource Interconnection” rules, and is expected to submit the proposal to FERC by the end of October. 

On the national stage, Senator Harry Reid, the Majority Leader from Nevada, has introduced a bill to promote renewable energy development.  The bill, S.2076, would require establishment of renewable energy zones and direct federal power administrations to identify the transmission needed to access renewable energy in the zones.  The prospects of the bill becoming law are uncertain.  At minimum, however, the bill signals increased awareness by senior policymakers of the need to foster transmission development to connect the nation’s vast renewable energy potential with the load centers in need of energy. 

Duquesne Complaint Dismissed in Time for October 1 PJM Capacity Auction

The Federal Energy Regulatory Commission (FERC) dismissed Duquesne Light Company's (Duquesne) complaint seeking to avoid participating in  the PJM Interconnection's (PJM)  scheduled October 1 Reliability Pricing Model (RPM) auction in which load servers are obligated to secure capacity reserves, and ultimately to withdraw from the regional transmission organization.

Among many deficiencies in Duquesne's complaint, FERC found that Duquesne failed to address "'the practical, operational, or other nonfinancial impacts . . . including, where applicable, the environmental, safety or reliability impacts of' PJM's exclusion of the Duquesne Zone load from the October 1 auction," as well as how reliability will be maintained if the load in its Zone is removed from the October 1 auction.

Importantly, FERC relied on both the PJM Transmission Owners' Agreement and the Reliability Assurance Agreement provisions that require that a load-serving entity seeking to withdraw from PJM must make a filing with the Commission under section 205 before that withdrawal becomes effective.  FERC ultimately found that it was the "necessary section 205 filing, rather than this complaint requesting relief on an emergency basis, [that] is the appropriate vehicle for resolving all of the issues related to Duquesne's withdrawal from PJM."  It remains to be seen whether Duquesne will make the withdrawal filing since avoiding participation in the October 1 RPM auction is no longer a motivating consideration.

Rising Capacity Costs Prompt Duquesne Light to Divorce PJM

Duqesne Light Company wants to sever ties with the PJM Interconnection regional transmission organization (RTO).  Duquesne cites the increased capacity costs resulting from PJM’s implementation of the new reliability pricing model (RPM) for capacity sales, and is asking FERC to allow it to withdraw before PJM’s next capacity auction that will cover 2009 deliveries.  PJM responded that it is too late to exclude Duquesne from that auction, and that numerous questions must be resolved, including how Duquesne would resolve it reliability requirements.  A number of others have likewise objected to Duquesne’s precipitous withdrawal. 

Duquesne has stated it intends to join the Midwest ISO, which it already borders from its location in Western Pennsylvania.  Of course, PJM is not the only organized market where member dissatisfaction has led to withdrawal.  Stating that a cost-benefit analysis compelled the conclusion, Louisville Gas & Electric and Kentucky Utilities left the Midwest ISO in 2006.  And due to unhappiness with capacity markets that mirror Duquesne’s complaint against PJM, the State of Maine has threatened to withdraw from NEPOOL and thereby ISO-New England. 

While utility membership in organized markets is voluntary, it is clear that withdrawals raise vexing issues of allocating costs to a shrunken customer base as well as long-term planning.  With the complex RPM market finally in operation, market participants are already being forced to examine a new twist, the impact of a utility’s withdrawal on capacity procurement and reliability.

FERC Finds PJM Not in Violation of Tariff in Months-Long Dispute with Customers over Independence of Market Monitor

In response to PJM Interconnection, Inc.'s (PJM) Offer of Settlement to resolve its much-publicized  dispute regarding the independence of PJM's Market Monitoring Unit (MMU) and allegations of tariff violations, interested parties on August 22 gave the Federal Energy Regulatory Commission (FERC)  a wide range of options to pursue in response to the Offer of Settlement, including: (1) setting the dispute for evidentiary hearing; (2) invoking settlement judge procedures; or (3) postponing action on the matter pending the agency’s action on the Advanced Notice of Proposed Rulemaking's goal to develop industry standards for the MMU structure. 

On September 20 FERC concluded that there was no evidence that PJM violated its tariff; thus no hearing was necessary.  Nevertheless, FERC ruled that the evidence was more than sufficient to demonstrate that the PJM MMU reporting requirements are unjust and unreasonable.  While the MMU before was under an "unusual degree of supervision" by PJM management, FERC directed in its order that, whatever other conclusion the parties may reach during settlement proceedings, the resolution must include provisions that the MMU report solely to the PJM Board or an independent committee of the Board.   Commissioner Suedeen Kelly noted in her statements that more specific tariff provisions are needed to promote a stronger working relationship between the MMU and its overseer and to engender confidence in market operations.

In its September 20 Order and Commission open meeting, FERC acknowledged and commended the complainants and Dr. Joseph Bowring for bringing this important matter to the Commission's attention, commended PJM Board's prompt and positive actions in promoting settlement discussions with its Offer of Settlement, and expressed its opinion that "a consensual resolution is most likely to restore confidence in the efficient, impartial and competitive operation of PJM's markets and in the monitoring of those markets."  Commissioner Jon Wellinghoff added that the pending rulemaking will help define the role of an MMU, but cautioned that it is PJM itself, in the settlement procedures with customers, that can best restore confidence in the markets PJM administers.  If not, then the agency made clear it is ready to step in and resolve structural and functional issues surrounding the PJM MMU.

UPDATE: PJM Proposes External Market Monitor to Quell Independence Issues

In an effort to resolve complaints concerning PJM management's alleged interference in the operations of PJM's internal market monitoring unit's (MMU) activities, last week PJM submitted to FERC a settlement proposal that would establish a fully independent external MMU.  The new unit would be modeled on the market monitor that FERC approved for the Midwest ISO, and would be a separate legal entity, unaffiliated with PJM.  PJM and the external MMU would enter into a contract, with an initial term of two years, for market monitoring services.  FERC approval would be required to replace the external MMU or decline to renew the contract. 

PJM is offering the head position at the external MMU to Joseph Bowring, the current internal market monitor whose earlier complaints about interference prompted two formal complaints, the resulting investigation currently underway, and the resignation of two PJM executives, including former PJM President and CEO Phil Harris. 

In a departure from the current, internal MMU structure, the proposed Settlement would grant the MMU explicit authority to file comments and testimony in FERC proceedings regarding PJM wholesale market issues, and the MMU alone would decide whether and how to respond to requests from FERC or state commissions for additional MMU data or analysis of the PJM market.  In a direct response to the complaints filed against PJM, the new external MMU would exercise exclusive control over data and information systems developed for market monitoring.  To provide continuity, until the external MMU is established, Bowring will continue to operate as the internal market monitor, and will report only to the PJM Board. 

High Cash Distributions of Master Limited Partnerships May Set Regulated Equity Return to Natural Gas Pipelines

In a July 19 proposed Policy Statement, the Federal Energy Regulatory Commission (FERC) floats the idea of substituting cash distributions that natural gas pipelines, organized as master limited partnerships (MLP), make to their partners for the corporate dividends that the agency uses in discounted cash flow (DCF) analyses to set regulated equity returns for natural gas pipeline companies.  The industry has long requested and anticipated this policy development since, increasingly, natural gas pipelines (like their oil pipeline cousins) have switched from traditional C-corporations to lower-taxed MLPs — from twice-taxed corporate dividends to once-taxed MLP cash distributions that tend to be higher.  If the Policy Statement is adopted, it may also affect equity returns of electric transmission systems, a number of which are considering switching from C-corporations to (MLP-comparable) real estate investment trusts (REIT).  To be considered, public comments on the proposed Policy Statement must be submitted within 30 days of publication in the Federal Register — sometime in late August.  A final Policy Statement is expected before year’s end.

Since corporate dividends distribute a portion of earnings, dividends have traditionally been a dependable indicator of where regulated returns on equity should be set, namely at a level that permits utility investors to earn a reasonable return on investment while also providing adequate funds for future growth.  Use of MLP cash distributions instead of corporate dividends is controversial in that those distributions can, and not infrequently do, exceed earnings and provide not only a return on investment but also a return of investment, which, if used in a DCF analysis, would award higher equity returns to natural gas pipelines, and possibly double recovery of some investments in the form of both equity return and depreciation.    (Presumably the same would be true if the cash distributions of an electric transmission REIT were used in a DCF analysis to set a transmission utility’s equity return.)

To address these concerns, FERC proposes two limitations on the use of MLP cash distributions in DCF analyses.  First, in order to be eligible for use in a DCF analysis, MLP cash distributions would be capped so that they could not exceed the reported earnings of an MLP natural gas pipeline — a return on, but not of, investment.  Second, a proponent of using MLP cash distributions in a DCF analysis would be required to produce and analyze multi-year data on the selected MLPs to show that cash distributions were not excessive and that earnings and growth were sustainable over time.

FERC Scrutinizes Organized Power Markets, but Proposes No Reforms for Now

Following a series of industry conferences on wholesale electricity markets, FERC issued an advanced notice of proposed rulemaking (ANOPR) aimed at exploring means of strengthening competition in organized power markets ― markets with spot energy sales and administered by regional transmission organizations (RTOs) or independent system operators (ISOs).  Public comments on the ANOPR will be due in mid- to late-August ― 45 days following publication in the Federal Register.

FERC is not aiming for a major redesign of RTO or ISO markets, but rather is focusing on four discrete issues on which the agency seeks advice:

• the role of demand response in organized markets, including possible rule changes to increase its use in times of emergency as well as through aggregation and for (or in lieu of ) ancillary services;  
• opportunities for long-term power contracting, including having the organized market operator serve as a clearing house for information on bilateral prospective bilateral deals;
• attributes of market monitors, including independence, enforcement authority, and reporting responsibility; and
• the responsiveness of RTOs and ISOs, in particular at the board level, to customers and other stakeholders.

Each of these issues relates to recent hot topics at the agency.  Commissioner Wellinghoff has become a vocal proponent of demand response.  An increasingly acrimonious dispute between PJM management and its market monitor has drawn attention to the role of market monitors, and in particular their independence.  The perceived remoteness of ISO and RTO boards has brought some calls for allowing market participants greater access to the boards.  And both energy users and project developers at times call for greater use of long-term contracts to stabilize prices.

After reviewing public comments on these topics, FERC will decide whether to issue a notice of proposed rulemaking to propose specific changes to its regulations governing power markets.

Market Monitor Continues Lobbing Shells at Defensive PJM Management

The recriminations between PJM management and its market monitor have reached a crescendo.  In a June 12 multi-volume response to FERC's investigation regarding PJM Interconnection's (PJM) alleged interference of its market monitoring unit (MMU), Dr. Joseph Bowring, PJM Market Monitor, supplemented allegations made in an April 5 statement that PJM management violated the MMU’s independence and compromised other objectives of the PJM tariff.  Among the specific allegations, Dr. Bowring charges that PJM management: (1) refused to prosecute a unit's exercise of market power that resulted in costs to market participants to the tune of $20 million; (2) pressured the MMU to modify its position on mitigating market power in the new RPM capacity market; (3) authorized confidential procedures that gave PJM management preferential review authority over MMU reports effectively modifying Attachment M to PJM's tariff, which contains PJM's Market Monitoring Plan; (4) ordered the Market Monitor to remove a central conclusion from its 2005 State of the Market Report; (5) sought to change or delay the release of four MMU reports from 2004 to the present. (6) ordered the MMU in 2005 not to post minutes of a recent Market Monitoring Advisory Committee (MMAC) meeting and in 2006 ordered the MMU to remove the discussion of a recent FERC Order regarding market monitoring form the MMAC meeting agenda; (7) prevented the MMU from analyzing the BGS auction for the New Jersey Public Utilities Commission in December 2006; and (8) replaced the Market Monitor with the VP of Markets at PJM as the Chairperson of the Cost Development Task Force, a group responsible for developing, reviewing, and recommending standard procedures for calculating costs of products or services for cost-based rates analysis .

Concurrently PJM submitted its own two-volume response to the FERC, dismissing Bowring’s criticisms.  Contrary to Dr. Bowring, PJM contends that “there is no factual basis for any claim that PJM has violated its tariff."  According to PJM, no one has alleged "that the MMU was ever prevented from performing any of its tariff-defined functions or reporting to the Commission any instances of market manipulation or other inappropriate conduct in the PJM markets."  Furthermore, PJM concluded that no evidence has been presented to demonstrate "that the market monitor was prevented from bringing to the Commission's attention matters of concern regarding the markets."  

Dr. Bowring also disclosed information he claimed points to PJM management's interference with MMU staffing, including targeting specific MMU employees for PJM Markets Division openings and threatening to eliminate MMU control over its data and data management.  According to PJM, however, it has provided the MMU with all appropriate staff to "carry out its tariff-defined functions," including maintaining its reliance on contract labor and adopting an especially aggressive and enhanced retention plan to encourage current MMU employees to remain with the MMU during the review period associated with the Complaint and this investigation.  

Regulators and market participants, particularly consumer groups, remain anxious about the MMU’s independence and effectiveness pending resolution of the charges and counter charges.

Former FERC Commissioners, Public Power and Customer Groups Clash over Competitive Electricity Markets

Developments in recent weeks have added fuel to the current debate over whether competitive wholesale electric markets have produced the promised benefits to customers.  On May 31, nine FERC alumnae — Chairs James Hoecker, Elizabeth Moler, and Pat Wood, and former Commissioners Vicky Bailey, Linda Breathitt, Nora Mead Brownell, Jerry Langdon, William Massey, and Donald Santa — circulated an open letter to policymakers lauding the achievements of competitive electricity markets and cautioning against proposals to turn back the clock.  The former Commissioners acknowledged that they knew it would "take time" for the full benefits of competition to be realized, and argued this has been especially true in states that imposed transitional conditions such as rate caps and because of the lack of transmission infrastructure development.  However, there have been substantial benefits from competition, including:  increased efficiency, lower costs (as evidenced by a study showing a purported $34 billion in savings to residential customers between 1997 and 2004), increased use of demand response, the facilitation of renewable resources, technological innovation, improved reliability, and satisfied customers (citing a recent letter to FERC from several large industrial consumers praising competition).  Responding to critics of competitive markets, the former Commissioners asserted that the "good old days" of pervasive cost-based regulation were not good for consumers, but rather produced high generation costs, low generator availability, declining infrastructure investment, and a resistance to technological innovation. 

Critics of current electricity markets answered the former Commissioners in a letter released on June 12, 2007.  The American Public Power Association (APPA) and the Electricity Consumers Resource Council (ELCON) purport to refute many of the former Commissioners’ claims.  They argue that "competition is in the eye of the beholder," and that just because they oppose the version of competition adopted by FERC and endorsed by the former Commissioners (presumably, a model centered around regional transmission organizations and organized spot markets) does not mean they oppose competition generally.  The problem, APPA and ELCON assert, is how competition has been implemented.  APPA and ELCON question the motives of the former Commissioners, many of whom APPA and ELCON contend work and schill for the "haves" in the electric industry, and criticize them for blaming high retail costs on misguided state regulators.  APPA and ELCON also question the study showing that consumers have saved $34 billion under competitive markets.  They also do not accept the common explanation that high electric costs have resulted entirely from higher natural gas and fuel costs, and argue that "satisfied" customers are few and far between.

FERC to Investigate Claims of PJM Management Interference in Market Monitoring

Long-Term Transmission Rights Arrive in Midwest ISO

The Energy Policy Act of 2005 (EPAct 2005) required FERC to enable load servers to obtain long-term transmission rights (LTTR).  Earlier versions of financial transmission rights offered in organized power markets were of short duration — typically monthly or yearly — which many load servers deemed inadequate for long-term planning and price certainty.  In its rulemaking to implement LTTRs, FERC directed organized market operators to prepare compliance plans consistent with FERC's guidelines.  Just as each organized market is idiosyncratic so too were the plans, and FERC is now addressing them, one by one.

In its plan, the Midwest ISO proposed not to allocated LTTRs directly to load servers, but instead to give them auction revenue rights (ARR).  A load server in the Midwest ISO can then choose whether to convert the ARRs to transmission rights or use them to collect the revenues from the sale of transmission rights in an auction.  The ARRs would have initial terms of one year each, but could be renewed annually for up to ten years.  FERC largely approved this approach. 

FERC went on to fault the Midwest ISO, however, for failing to fund fully its LTTR —that is, to ensure that the financial coverage offered would not change during its term.  While the Midwest ISO proposal would fully fund the ARRs, the associated transmission rights would not be fully funded, which could expose transmission users to revenue shortfalls, for example, when a transmission line goes out of service.  FERC directed the Midwest ISO to propose means for ensuring the transmission rights holder is fully compensated in all such instances. 

PJM was the first organized market operator to submit an LTTR compliance filing to FERC.  FERC approved PJM's LTTR proposal last fall, but also found that PJM had not met the full funding requirement.  PJM revised its proposal to use an "uplift" mechanism that distributes the shortfall costs to all financial transmission right holders to provide the revenue protection, and FERC sanctioned that approach. 

FERC also denied the demand of the Long Island Power Authority that it be allowed to obtain LTTRs in the PJM service territory.  LIPA only serves load outside the PJM territory, and PJM denied its requests for LTTRs.  LIPA argued its request was consistent with the EPAct and justifiable because it pays for its share of necessary transmission upgrades as well as the transmission service charge that covers the embedded costs of PJM transmission.  FERC agreed with PJM but not on the ground that LIPA only served load external to PJM.  Instead, FERC found that LIPA failed to meet the PJM prerequisite of having taken transmission service during a given reference year in the past and paying the embedded costs of the PJM transmission system. 

DC Circuit Remands ISO-NE Installed Capacity Orders to FERC

The US Court of Appeals for the DC Circuit on April 20 issued a per curiam order that sends back to FERC the issue of whether the agency has jurisdiction to authorize ISO-New England's (ISO-NE) implementation of an installed capacity requirement.  The Connecticut Attorney General Richard Blumenthal and the Connecticut Department of Public Utility Control (CDPUC) had challenged FERC's jurisdiction over the contentious installed capacity requirement, which obligates load servers to control capacity in excess of peak load.  The AG and CDPUC argued that the Federal Power Act (FPA) entrusted such power supply decisions to the states, and not the federal government, to decide such matters.  While the court did not necessarily agree with the Connecticut parties' arguments that installed capacity is really a form of generation resource adequacy that should be left to the states, it directed FERC to articulate a justification for federal jurisdiction.

The AG and CDPUC have been vehement opponents of the installed capacity proposal from the outset.  In its briefs to the court, the CDPUC attempted to downplay the relationship of installed capacity requirements to wholesale rates, indicating the connection was only "tangential[] or incidental[]."  The CDPUC sought a court order defining the scope of FERC's authority over generation resource adequacy and directing that FERC must defer to Connecticut's jurisdiction regarding the generation capacity requirements.  For its part, FERC countered that authority over generation capacity was conferred to it by the FPA's general grant of federal jurisdiction over the sale of electric energy in interstate commerce.  But that wasn't clear enough for the court, which accordingly remanded the case back to FERC.  However, the court did not go as far as the CDPUC and AG would have liked; by simply remanding to FERC for further explanation of its jurisdiction, the court gave FERC another shot to explain how and why it should regulate installed capacity, and it left for another day the merits of ISO-NE's proposal.

FERC Tailors Transmission to Connect Renewables

In response to a carefully crafted petition from the California Independent System Operator, the Federal Energy Regulatory Commission took a large step toward facilitating development of the transmission needed to harness wind and other renewable energy sources that are remote from load centers.  With its order granting the CAISO’s petition for declaratory order, FERC approved a financing mechanism that is intended to solve the "chicken or egg" sequencing problem of development of transmission lines and renewable energy generators in areas such as the Tehachapi region of California.

The problem vexing renewable energy advocates is that wind, geothermal and other renewable generators must be built where natural conditions allow.  But wind and geothermal hot spots are often far from the energy-thirsty urban centers, and little transmission is available at these remote locations.  Since most renewable energy projects are much smaller than large hydro or fossil-fuel plants, individual generators can’t afford to develop major new transmission projects.  Nor have transmission owners been keen on building lines to locations where the development of generation is either marginal or uncertain. 

To break this transmission logjam, some states have created transmission development agencies.  But California entities have focused more on creating cost recovery mechanisms that would allow the state's transmission-owning utilities to develop the transmission themselves.  In 2005, Southern California Edison initally proposed a "trunk line" model, but FERC objected  because ratepayers would pay for the entire facility, and because the utility would retain control of it.  FERC solicited an alternative, and the CAISO responded with a program having the following key terms:

• The project must provide access to an area with significant potential for development of remote energy resources.
• Initial costs of qualifying interconnection facilities would be rolled into the transmission revenue requirement of the transmission owner that constructs the facility, subject to a cost cap to protect ratepayers. 
• Later costs would be paid pro rata by generators who interconnect with the line.
• The project would have to be approved through the CAISO transmission planning process.
• A minimum level of generators must commit to the line before it can proceed, and another batch must have shown interest in joining. 

FERC earlier had resisted advantaging renewable energy through favorable transmission rules.  But with its approval of the CAISO program, FERC acknowledges that location-constrained resources are unique and warrant different access rules. 

FERC Dismisses CARE Complaints, Defends Market-Based Rate Program

In an order issued at its April 19 meeting, FERC dismissed two of several pending complaints by the CAlifornians for Renewable Energy (CARE) that urged FERC to abrogate two contracts:  one between Southern California Edison (SCE) and Long Beach Generation, and the other between Pacific Gas & Electric (PG&E), Metcalf Energy Center, and Los Medanos Energy Center.  The California Public Utilities Commission (CPUC) approved both of the contracts as part of its resource adequacy program.  CARE argued that, based on the Ninth Circuit's 2004 decision in State of California ex rel. Lockyer v. FERC and its recent "Long-Term Contracts" decisions (Snohomish PUD v. FERC and CPUC v. FERC), the PG&E and SCE contracts at issue were not just and reasonable and had not been pre-filed with FERC for approval, and thus were not entitled to protections of the long-standing Mobile-Sierra doctrine.  While FERC could have dismissed CARE's complains based on their lack of real factual support or development, the Commission took the opportunity to address the merits of CARE's assertions regarding the meaning of the Ninth Circuit decisions.

FERC defended its market-based rate program on several grounds:  First, FERC emphasized that the court in Lockyer had actually upheld FERC's market-based rate regime.  According to FERC, Lockyer's holding was that the Commission had failed to properly oversee the dysfunctional California energy markets during the 2000-2001 crisis by ensuring adequate compliance with its reporting requirements, meaning that sellers could be subject to retroactive refunds for those sales.  Addressing the Long-Term Contract cases, it appears that FERC's view is a narrow one, i.e., that the court held that the Mobile-Sierra protection will apply when certain factors have been met, including whether FERC provided adequate oversight of the markets in which contracts were negotiated and whether it considered changed market circumstances in deciding whether contracts negotiated in those markets remained just and reasonable. 

FERC also defended its efforts to improve the markets, emphasizing its approval of a significant overhaul of the California market (the MRTU market design);  FERC's enhanced reporting requirements, market oversight, and increased enforcement authority to address manipulation; FERC's guidance regarding reporting to the various price indices; and the Commission's ongoing effort to strengthen its market-based rate program.  FERC made clear that it considered the California crisis to be a "perfect storm" of events that are unlikely to reoccur in the future.  FERC thus determined that the contracts here did not need to be submitted for prior review, testing whether the Ninth Circuit meant what it said when it held that the market-based rate program is still valid as long as certain protections are in place.  Of course, the court has yet to bless many of these reforms, so it remains to be seen whether FERC's efforts will be sufficient.

PJM Board Orders Investigation after Market Monitor Challenges PJM Management over Independence

At a FERC conference on the role of market monitors in the power industry, a simmering dispute between PJM Market Monitor Joe Bowring and PJM management surfaced when Mr. Bowring accused PJM management of interfering with its independence.  The role of market monitors, including their chain of command, was the key issue in the conference.  Moving past more academic concerns, Mr. Bowring aired his dispute with management.

In oral and written comments delivered to the Commissioners, Mr. Bowring said that while PJM is independent from market participants, PJM, as an organization, has specific interests, which may differ at times from the Market Monitoring Unit's (MMU) goal of providing objective, critical evaluations of markets, of market participants, and of PJM itself.  He said PJM management had ordered changes to the State of the Market Report that is filed with FERC, and also prevented him from presenting to PJM members analyses with which management disagreed.  He also charged PJM management with delaying the release of an MMU report that management opposed.

Mr. Bowring recommended that to ensure the MMU's independence, its employees not be part of the "chain of command" from PJM management.  He stated, however, that PJM appeared to be more interested in hiring outside consultants to perform the market monitoring function.  FERC Chair Joe Kelliher ― who stated he had not previously been aware of this dispute ― asked Bowring to whom the market monitor should report, and suggested that regarding this dispute PJM's side of the story should also be heard.

"Back to the Future" Debate Continues at FERC on State of Competition in Wholesale Power Markets

On the heels of moves in several states to "re-regulate" electric markets, and complaints from consumer advocates that electric competition has not brought about promised savings, FERC has embarked on a series of public conferences regarding the status of competition in wholesale electric markets, the first of which was held February 27.  Panelists at the first conference included speakers from both sides of the competition debate, who took predictable positions in their public remarks.  Economists and sellers argued that the "good old days" before competition were not nearly as good as critics of deregulation would have us believe.  Public power, customers, and consumer interest groups, on the other hand, argued that organized markets have done nothing but raise prices and recommended going “back to the future.” 

A few of the more interesting moments came when panelists broke from their traditionally expected positions or from their prepared remarks.  Wal-Mart representative Angela Beehler praised organized markets as having helped the company to lower its massive electric bills. Several panelists asked the Commission to reexamine the use of single-price auctions.  PNM Resources CEO Jeff Sterba asked FERC to help overcome state parochialism that limits the availability of renewable energy credits (RECs) for out-of-state renewable resources, and to create, or at least support, markets for trading RECs. 

The Commissioners asked the panelists numerous questions, without offering any real insights into specific reforms that the Commissioners may have in mind, but at the same time belying their personal perspectives.  Despite promising in his opening remarks that the Commission is not wedded to the status quo, Chairman Kelliher seemed quite satisfied with the existing state of wholesale electric markets, in which organized and bilateral markets coexist.  He asked several panelists how it would be possible for FERC to put the "genie back in the bottle," that is, require utilities to "re-bundle" assets that were sold off during state unbundling initiatives over the last decade.  Deregulation critics answered this with deafening silence.  On the flip side, Commission Spitzer asked whether there were any incentives for low-cost jurisdictions that currently are in bilateral markets to incur the expense of joining organized markets.  Commissioner Moeller focused on the issue of whether high prices were not merely the result of high natural gas prices, a position adopted by many of the panelists representing generators and economists, but disputed by those like Joe Nipper of American Public Power Association, who testified that APPA had performed a study finding that gas prices were not the only, or even the primary, driver of high electric prices.  Several of the Commissioners also focused on opportunities for organized markets to enhance renewable energy and demand response. 

The next of FERC's public conferences on wholesale markets has not yet been scheduled.

Senator Investigates Recent Natural Gas Price Volatility

Citing the "critical consumer protection issue" of natural gas price volatility, on February 6, Senator Jeff Bingaman (D-NM) sent letters to FERC Chairman Joseph Kelliher and Commodity Futures Trading Commission (CFTC) Chairman Reuben Jeffrey, posing a series of questions to both agencies about how they monitor gas futures trading on the New York Mercantile Exchange (NYMEX) and on the Intercontinental Exchange (ICE).  The Senator, who is the current chair of the Senate Energy and Natural Resources Committee, also asked for the agencies' cooperation in monitoring future market activity. 

At the heart of Senator Bingaman's concerns were price volatility seen at the end of January, as well as last fall's collapse of hedge fund Amaranth.  Amaranth, which had large positions in financial natural gas markets, lost hundreds of millions of dollars when it bet in the wrong direction on gas prices.  In the wake of the collapse, some at the company expressed concern that the markets had been subject to manipulation.  Senator Bingaman also cited a recent GAO report, which found that gas commodity prices have risen 190% since 1993 and that more of these costs are being passed on to end-use consumers. 

In his letter to Kelliher, Senator Bingaman asked how FERC can continue to find contract prices pegged to NYMEX price indices "just and reasonable" in light of this increased price volatility.  Senator Bingaman also highlighted the increased authority given to FERC by the Energy Policy Act 2005 to review transactions in financial markets, as well as the increased cooperation promised by FERC and the CFTC in an October 2005 Memorandum of Understanding.  The letter to CFTC focused additionally on whether ICE had been responsive to recent requests by CFTC for information related to the Amaranth collapse.

California ISO Proposes Transmission Tailored to Renewable Energy

Picking up where one the state’s biggest utilities left off, the California Independent System Operator (CAISO) has proposed to FERC a new category of transmission that would facilitate development of renewable energy  ― particularly wind ― in regions short of adequate transmission capability.  If approved by FERC, the new type of transmission could bring on line further development of the productive Tehachapi region and help the state achieve its ambitious renewable portfolio standards. 

Driving the CAISO proposal is the fact that many of the most promising sites for wind energy development are far from existing transmission lines.  FERC’s transmission policies allocate most interconnection costs to the generator, which works against developers of remote wind farms.  The CAISO would lessen this entry barrier by allocating the initial costs of developing a multi-user interconnection line, or trunkline, to the regional transmission owner who, in turn, would recoup those costs over time through the CAISO’s transmission access charge.  Interconnecting generators would then pay their pro-rated share of the line’s costs once they start operations.  Other elements of the proposal are intended to limit cost impacts on ratepayers and ensure this type of transmission is used only for major projects.  

The proposal follows the efforts of Southern California Edison, which in 2005 sought FERC approval for rolling in the costs of a trunkline intended to allow interconnections with wind projects in the Tehachapi region.  In a split decision, FERC rejected the proposal on the grounds that the proposed roll-in did not benefit all transmission users, but there were indications that a proposal by the CAISO might be received more favorably. 

The leader in wind generation, Texas, has taken another path for developing needed transmission.  It will designate renewable energy development zones based on renewable energy potential, and then mandate transmission development from the zones to more populated areas.  Since most of Texas is not subject to FERC’s jurisdiction, however, that proposal did not require Washington's blessing.

Separately, FERC has been conducting a rulemaking to revise its Order 888 open-access tariff.  As part of the rulemaking, FERC has considered requiring transmitting utilities to offer a new category of conditional firm transmission service that would benefit wind and other intermittent sources of energy.  FERC is scheduled to discuss the rulemaking at its upcoming February ­­15 meeting and a final order will likely issue soon thereafter. 

FERC Approves Controversial Settlement on PJM Capacity Rules

Praising the settlement process as much as the results, the Federal Energy Regulatory Commission approved, subject to certain changes, the settlement that the PJM Interconnection reached with market participants for a redesign of PJM's capacity market.

PJM's August 2005 proposal to FERC led to an order in which FERC concluded the existing capacity rules were unjust and unreasonable.  This led to settlement negotiations, encouraged by FERC, and the submission of a settlement agreement supported by a majority of market participants.  The settlement was based on the proposal PJM submitted to FERC in August 2005, but included expanded provisions deemed suitable for vertically integrated utilities.  Among the key provisions of the agreement are a sloping demand curve (which combined with generator bids determines capacity prices), forward (rather than same-year) procurement of capacity, and ultimate use of 23 locational deliverability areas (LDAs) reflecting transmission constraints, to be phased-in over several years – which some generators contended was discriminatory because of the use in the interim of an aggregated Rest-of-Market LDA that contains significant internal constraints. 

FERC To Take Closer Look at ISO-NE's Proposed 2007 Budget

The cost of running regional transmission organizations continues to be a point of contention.  FERC has agreed with New England officials representing Massachusetts, Connecticut, Maine and New Hampshire that part of ISO-New England's proposed budget for 2007 deserves more scrutiny, and has established a paper hearing to evaluate the proposal. 

In October, the ISO-NE submitted tariff sheets for recovery of an expected $114.9 million revenue requirement for 2007.  For the third year in a row, challenges were levied against ISO-NE's proposed budget.  The New England officials asked FERC to hold a trial-type evidentiary hearing to determine whether the costs that ISO-NE plans to pass through to customers, were just and reasonable.  In arguing that ISO-NE failed to support its  budget, the regional officials pointed to FERC's statement last year in its Final Rule on Accounting and Financial Reporting for Public Utilities and RTOs  that the changes in financial reporting implemented by that rule should improve cost recovery practices by providing greater detail concerning RTO costs.  In particular, the officials challenged  ISO-NE's proposed senior staff incentive payments, depreciation and amortization expenses, non-project capital expenses, consultant and other professional service fee costs, and costs related to projected staffing increases.

The only issue set for hearing is ISO-NE's proposed depreciation and amortization expenses.  In particular, FERC ― like the New England officials ― questioned whether the "relatively short average service lives and zero net salvage values used by ISO-NE may result in excessive amounts of depreciation and amortization" for the coming year.  FERC found all of the other complaints to be unfounded or not properly at issue.

Other recent challenges to ISO-NE budgets have not succeeded.  Last year, FERC rejected challenges to rate recovery of certain lobbying costs, and in 2005 FERC justified the increase in ISO-NE's administrative costs based on additional duties taken on by the RTO.  As seen again here, FERC's concern for accurate RTO budgeting does not necessarily translate into reduced rates for RTO services.

Texas Coop Plans New DC Tie Between ERCOT and SPP

Brazos Electric Cooperative (Brazos) applied to FERC in October and again in November for the interconnection of a new 70-mile, 345 kV transmission line that would connect generation in Oklahoma with load in Texas.  The proposed line would be built in conjunction with Brazos's plans to construct a new 750 MW coal-fired generating unit near the Western Farmers Electric Cooperative's (WFEC) existing Hugo generating facility in Hugo, Oklahoma.  Brazos, an electric coop located in 68 counties across north Texas, and WFEC, which has service areas throughout Oklahoma, will jointly own the new Hugo unit.  In order for Brazos to bring this power from Hugo to the Electric Reliability Council of Texas (ERCOT), Brazos is planning to build the new DC intertie between ERCOT and the Southwest Power Pool (SPP), which will have an approximate capacity of 375 MW.  Accordingly, Brazos has asked FERC to order TXU Electric Delivery (TXU) to allow it to interconnect with TXU's system at the Valley South substation in north Texas.  Brazos also asked FERC to require TXU and CenterPoint Energy Houston Electric to offer transmission service for power flows over the new line into or out of ERCOT.  Brazos has asked FERC to issue a decision on its application by January 31, 2007.

The proposed DC intertie would be the third such interconnection between ERCOT and SPP.  In its application, Brazos took pains to emphasize that its proposed interconnection would maintain the fiction that ERCOT is outside of the interstate grid and not subject to most forms of FERC regulation.  To that end, Brazos specified that the intertie and the generating unit's switching station would be engineered such that the generating facility could generate only into either ERCOT or SPP, but not both at once.

CAISO Considers Delaying MRTU Again

Regional Operators Enjoy Flexibility in Selecting Cost Allocation Methodology

Disputes in the Midwest over allocating transmission costs date back to at least the mid 1980s, when competing interests fought over AEP's transmission equalization agreements and the transmission costs associated with the Rockport plant.  Recently FERC resolved for now another of those disputes, by accepting Midwest ISO's proposed allocation of the costs of new transmission infrastructure. 

Midwest ISO proposed to allocate the cost of: (1) lower voltage lines subregionally to all transmission customers in the designated pricing zones affected by the transmission project, and (2)  Extra High Voltage (EHV) ― 345 kV up to 765 kV ― 80% subregionally (like lower voltage facilities) and 20% systemwide on a load-ratio share basis (i.e., a postage-stamp basis).  FERC accepted this allocation on the ground that the EHV lines are the superhighways of the Midwest transmission grid. 

Midwest ISO is the third RTO for which FERC has engaged transmission cost allocation issues.  The others are New England and Southwest Power Pool.  FERC accepted a different approach for each.  Given that FERC has been flexible in allowing different approaches, future RTOs will be free to seek their own solutions to these often divisive issues. 

FERC also accepted Midwest ISO’s proposal for generation interc